On March 17, 2017, at approximately 1517 EDT, during refueling operations on Unit 1, power was being restored to the Open Phase system for the 1-B Reserve Auxiliary Transformer (RAT). During restoration, a valid undervoltage actuation signal was sent to the 1-B Emergency Diesel Generator (EDG). The EDG automatically started and tied to the safety bus.

This undervoltage condition was caused by a wiring error in the Open Phase system to the 1-B RAT.

Unit 1 was in Mode 6 at the time and remained so throughout the event. There was no change in the decay heat removal for the plant.

Because this event resulted in the automatic actuation of a system listed in 10 CFR 50.73(a)(2)(iv)(B), this event is reportable under 10 CFR 50.73(a)(2)(iv)(A). This event had no adverse effect on the health and safety of the public, and is of very low safety significance.

On March 14, 2015 at 1207 Eastern Daylight Time (EDT), Unit 2 was operating in Mode 3 following an unplanned reactor trip and safety injection, a valid Auxiliary Feedwater (AFW) actuation signal was received on B-train Auxiliary Feedwater system during post-trip recovery and unit stabilization. Both Train A and Train B motor driven AFW pumps were in service at the time. Upon receipt of the AFW actuation signal the B-train discharge valves stroked to the full open position. Operators immediately restored AFW discharge valves to their previous positions without any adverse impacts on the unit.

The plant remained in Mode 3 and decay heat continued to be removed via the Atmospheric Relief Valves.

Unit 1 was unaffected. This event had no adverse effect on the health and safety of the public, and is of very low safety significance. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of a system listed in 10CFR 50.739a)(2)(iv)(B).

On March 14, 2015 at approximately 04:29 AM Eastern Daylight Time (EDT), Vogtle Unit 2 was operating in Mode 1 at 100 percent power when the Loop 3 outboard Main Steam Isolation Valve (MSIV) spuriously closed. The sudden closure of the steam isolation valve caused a rapid pressure reduction in the remaining three Steam Generators (SGs) due to increased steam flow resulting in a Reactor Protection System (RPS) actuation due to rate compensated Low Main Steam Line Pressure Safety Injection and Steam Line Isolation. All control rods fully inserted and all equipment actuated as designed.

The unit was stabilized in Mode 3 with decay heat being removed through the atmospheric relief valves (ARVs) to the environment. The Loop 3 MSIV closure was due to failure of the hydraulic dump solenoid valve which resulted in a loss of hydraulic pressure to the MSIV.

This event had no adverse effect on the health and safety of the public, and is of very low safety significance. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of a system listed in 10CFR 50.739a)(2)(iv)(B). Unit 1 was unaffected.

On July 27, 2014 at approximately 1409 Eastern Daylight Time, Vogtle Unit 1 was operating in Mode 1 at 100 percent power. While surveillance testing was being performed on the Main Feed Pump A (MFP A) a control oil leak developed in the lockout solenoid valve. The reduced control oil pressure resulted in a reduction of feed pump speed. Control Room Operators observed lowering feedwater flow to the Steam Generators and manually actuated the Reactor Protection System (RPS) system which resulted in a turbine-generator trip. All rods fully inserted into the core, the Main Feedwater Isolation system and the Auxiliary Feedwater system automatically actuated as expected. The unit was stabilized in Mode 3 and decay heat was discharged to the condenser. The cause of the event was a failure of the trip lockout solenoid valve which led to reduced pressure on the trip relay for MFP-A which reduced the speed of the pump and consequently the total feed flow to the Steam Generators.

The safety significance of the event is very low. Unit 2 was not affected and there were no adverse effects on the health and safety of the public.

Reported lessons teamed are incorporated into the Ficensitv process and fed back to industry.

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On April 8, 2014 at approximately 04:30 Eastern Standard Time, Vogtle Unit 2 was operating at Mode 1 at 100 percent power when Unit 2 received a Steam Generator 3 narrow range low-low level automatic Reactor Protection System actuation as a result of the Loop 3 Main Feedwater Regulating Valve failing closed. The RPS actuation resulted in a trip of the turbine-generator. All rods fully inserted into the core, the Main Feedwater Isolation system and the Auxiliary Feedwater system automatically actuated as expected. The plant was stabilized in Mode 3 and the decay heat was discharged to the condenser. The cause of the event was a failure of the Steam Generator 3 Main Feed Regulator Valve control system.

The safety significance of the event is very low. Unit 1 was not affected and there were no adverse effects on the health and safety of the public.

On November 27, 2013, an internal wiring discrepancy was discovered on Class 1 E battery charger 1AD1CB (EJ) following the trip of the battery charger AC input breaker.

The wiring discrepancy prevented the battery charger from performing all required functions of LCO 3.8.4, DC Sources - Operating. One of two redundant battery chargers and one battery per train must be operable to meet the requirements of LCO 3.8.4. Subsequent review of battery charger maintenance activities determined that on September 30, 2013 the remaining redundant operable battery charger was removed from service for maintenance activities for approximately 14.5 hours.

LCO 3.8.4, DC Sources - Operating requires restoration of the inoperable DC source within 2 hours or entry into Mode 3 within the next 6 hours, and entry into Mode 5 within the following 30 hours. Although the degraded charger was able to maintain battery terminal voltage within limits under minimal loading condition, the DC source was inoperable for a time greater than allowed by Technical Specification.

The safety significance of this event is very low. Unit 2 was not affected and there were no adverse effects to the health and safety of the public.

On February 26, 2013, at approximately 2302 Eastern Daylight Time (EDT) time, with Unit 2 operating in Mode 1 at 94 percent rated thermal power and End of Life (EOL) Coastdown in progress, Unit 2 operators initiated a manual reactor trip due to Reactor Coolant Pump (RCP) #4 number one seal leakoff flow exceeding the operating limits. The Reactor Trip System, the Engineered Safety Feature Actuation System, and other responding equipment performed as expected. The plant was stabilized in Mode 3. The cause of the event was the addition of air into the Chemical Volume Control System (CVCS) charging system as a result of less than adequate filling and venting of the Reactor Coolant System filter.

The safety significance of this event is low. Unit 1 was unaffected and there were no adverse effects on the health and safety of the public.

Vogtle Unit 1 experienced a mismatch in secondary steam flow during power ascension from 2% to 10% reactor power (Mode 2 to Mode 1). The control room operators confirmed the mismatch by observing divergence in reactor coolant system loop differential temperatures, secondary steam pressures, and secondary steam flows between loops one and four and loops two and three. At this time, the reactor was manually shutdown. Subsequent investigation determined the outboard main steam isolation valve on main steamlines two and three were indicating open in the Main Control Room when, in fact, the valves were closed. Neither the safety of the plant nor public health and safety were affected by this event.

On October 5, 2012 with Unit 1 in Mode 5 and the residual heat removal (RHR) system in service for reactor coolant system temperature control, activities were in progress in preparation for Mode 4 entry. One of the activities involved restoration of the steam generator level RPS/ESFAS instrumentation from a bypassed condition to normal alignment. During the restoration a steam generator lo-lo level actuation was received and the motor-driven auxiliary feed water (AFW) pumps started and two turbine-driven AFW discharge valves stroked full open. The AFW system had previously been removed from service per the controlling unit operating procedure; however, following safety system testing during the outage the AFW system was not properly aligned to prevent inadvertent actuations. Neither the safety of the plant nor public health and safety were affected by this event.

On February 15, 2012, with the unit at 100 percent power, it was determined that opening the boundary valve between the safety related and seismically qualified Refueling Water Storage Tank (RWST) and the non safety related and non seismically qualified Spent Fuel Pool Purification (SFPP) system in Modes 1-4, renders the RWST inoperable. Plant procedures had been revised In 2009 to allow opening this boundary valve in Modes 1-4 under administrative controls. The 10 CFR 50.59 safety evaluation that had been performed to support the procedure change had concluded that the administrative controls would allow the RWST to remain operable. However, in consideration of the new interpretation provided in NRC Information Notice 2012-01, it was judged that the RWST would be considered to be inoperable regardless of the administrative controls established when the RWST was aligned to non-seismic piping in Modes 1 - 4. Since the boundary valve had been opened in Mode 1 under administrative controls and the one hour completion time of Technical Specification 3.5.4 Condition D was not entered, under this recent interpretation, this represented a condition prohibited by Technical Specifications and is reportable pursuant to 10 CFR 50.73(a)(2)(I)(B). This event had no significant safety consequence since a seismic event had not occurred while the SFPP system was in service on the RWST.

On August 31, 2011 with Unit 1 operating in Mode 1 at 100 percent rated thermal power at approximately 0906 hours Eastern Daylight Time, the Unit 1 reactor automatically tripped. In preparation for maintenance on the controls for the main feedwater regulating valve (MFRV) on steam generator (S/G) 2, the valve was placed on an air gag. The air gag maintains the MFRV in position and allows minor changes in steam generator water level to be controlled by the bypass feedwater regulating valve (BFRV). However, shortly after the air gag was installed, feedwater flow to S/G 2 increased beyond the capability of the BFRV to control. The increase in feedwater flow to S/G 2 resulted in water level on S/G 2 exceeding the Hi-Hi nominal trip setpoint (NTS). This caused a main feedwater isolation, turbine trip and subsequent reactor trip in accordance with plant design.

The cause of the event was due to increased air pressure being supplied to the MFRV when the valve was placed on the air gag. The first corrective action was revising the procedure to ensure calibrated test gauges are used to determine the pressure setting of the regulator for the air gag and for an operator to be present while the MFRV is controlled by the air gag. The second corrective action is to replace the contact type potentiometer used in the MFRV control circuit which has been proven unreliable.

On August 23, 2010 an Operations Superintendent was reviewing past performances of the reactor trip breaker surveillance test in preparation for an upcoming surveillance test on a reactor trip breaker.

During this review it was determined that on January 28, 2010 the 2B Solid State Protection System (SSPS) Mode Selector switch was placed in Test to perform a surveillance test on the 2B reactor trip breaker. Placing the 2B SSPS Mode Selector switch in Test defeats the Engineered Safety Features (ESF) automatic actuation signal to the 2B train components. At the time 2B SSPS Mode Selector was placed in test, the 2A high head safety injection (HHSI) pump was tagged out of service for planned maintenance. In this configuration, both trains of HHSI were rendered inoperable and outside the Conditions stated in Technical Specification 3.5.2, since neither train would have automatically started on an ESF actuation signal. Although not recognized at the time of the event, this condition required entry into Technical Specification LCO 3.0.3.

The cause of this event was due to an inadequate Loss of Safety Function (LOSF) determination, as described in Technical Specification 5.5.15, being performed and the work planning process not adequately identifying potential Technical Specification implications for the scheduled work.

On April 21, 2008 at 0951 EDT, Unit 1 entered Mode 3, from Mode 4, with the pressurizer heaters in Group A inoperable. Unit 1 entered Mode 3 in a condition prohibited by Technical Specification (TS) 3.0.4. The condition was identified during a pressurizer heater capacity test on April 21, 2008 at 1818 EDT, when a Maintenance electrician observed open breakers on the Group A and C heater panels. The Unit 1 Control Room was immediately notified, and Operations entered a Required Action statement for TS 3.4.9, based on inoperability of pressurizer heater Group A while in Mode 3. The heater breakers were subsequently closed within the 72-hour Required Action statement.

The primary cause of this event was inadequate work instructions to perform the necessary pressurizer heater work. The functional testing requirement to complete heater resistance measurements was not properly planned in the work order to ensure that the equipment was properly tested before being placed in service. In addition, human performance tools were not used by the individuals involved in the manipulation of the breakers when it was determined the instructions were not adequate. The supplemental electrician associated with the pressurizer heater breaker mispositioning event was unaware of the plant procedure used to document breaker manipulation.

The week of June 6, 2005, a Vogtle Equipment Qualification Program self-assessment was performed that identified a potential problem with the Rosemount model 1153 Series B and 1154 transmitters if the neck seal is broken. This seal protects the transmitter electronics from moisture intrusion to ensure the safe operation of the transmitter during accident conditions. This self-assessment resulted in the development of an inspection plan to determine if this condition existed at Vogtle. The inspection plan was initiated in June 2005 and completed in August 2006. The following three Technical Specification (TS) instruments were determined to have been inoperable as a result of a broken neck seal: 1FT-5152, Steam Generator (SG) 1 Auxiliary Feedwater Flow, 2PT-0455, Pressurizer Channel 1 Pressure, and 1PT-0456, Pressurizer Channel 2 Pressure.

Per the vendor manual, the connection between the electronic housing and the sensor module is hermetically sealed with a baked-on environmentally qualified neck seal. The cause of the event was a result of inadequate installation and calibration procedure guidance in that a caution statement from the vendor manual not to break the neck seal between the sensor module and the electronics housing was not included. All three transmitters were replaced, and appropriate maintenance procedures have been updated to reflect the vendor manual caution to not rotate the head.

On April 15, 2006, while at 100% power, the Unit 1 Control Room crew was challenged by an erratic response of the Loop 3 Main Feed Regulating Valve (MFRV), 1FV0530, while operating in automatic.

The crew was able to stabilize the valve in manual mode, however, over the next 24 hours the control of the valve continued to degrade. On April 16, 2006, it was decided that Unit 1 would be taken to Mode 3 for investigation of the control issue with 1FV0530. On April 17, 2006, at 0026 EDT, Unit 1 was manually tripped at 33% power when Steam Generator number 3 water level was observed to be slowly increasing with 1FV0530 unable to control level in either automatic or manual.

A review found that 1FV0530 operated erratically due to a failed I/P transducer, which resulted in the inability to reduce feedwater flow requiring a manual reactor trip. Based on the results of the observations and failure analysis performed on the I/P transducer, two failures were identified. One failure was the supply air input connector and the resultant electrical to pneumatic conversion process for a valve internal to the controller, and the second failure was the electronic circuit board. The failed transducer and the remaining Unit 1 MFRV I/P transducers were replaced with different make and model I/P transducers prior to the unit restart.

On February 1, 2006, control room operators received indication of an increase in radioactivity in the containment atmosphere. On February 3, 2006, a robotic camera observed leakage inside the bioshield wall in the area of reactor coolant system (RCS) loop 1. Unit 2 was placed in Mode 3 (Hot Standby) at 1806 EST, on February 3, 2006, to allow further investigation of specific leakage locations. At 2124 EST, this investigation found RCS pressure boundary leakage at two welded connections on a 'A" bypass line around the Residual Heat Removal (RHR) loop suction valve, 2HV 8701B, and shutdown to Mode 5 (Cold Shutdown) was initiated. On February 5, 2006, at 0035 EST, Unit 2 entered Mode 5 to comply with Technical Specification 3.4.13.a. due to the RCS pressure boundary leakage.

Although the cause of the weld failures is undetermined at this time, the root cause investigation is still underway. Issues being addressed include high vibration of the bypass line, support design, excessive weld stress, and weld quality. The theory presented by the root cause team is the cause of the cracks was from high cycle fatigue. Corrective actions included replacement of the Loop 1 bypass line, inspection of supports and snubbers for both Unit 2 bypass lines, inspection of welds on the Loop 4 bypass line, and installation of monitoring instrumentation. Following additional monitoring, the cause determination will be completed, follow-up corrective actions implemented and a revised LER will be submitted by July 11, 2006.

Reactor Coolant System Loop 2 Overtemperature Delta-T (OTDT) instrument channel 2T-421 was restored to service on February 26, 2005, following maintenance to correct overtemperature setpoint (OTSP) drift by replacing a summing amplifier. After the channel was returned to service, the OTSP signal continued to drift until March 3, 2005, when 2T-421 was again removed from service and a different summing amplifier replaced, correcting the drift anomaly. On July 21, 2005, an engineering evaluation of the instrument channel drift evolution concluded that this channel's OTSP signal had drifted outside of the Technical Specifications (TS) allowable values for the input signals for a period of time longer than allowed by the action requirements. Therefore, the unit had operated in a condition prohibited by the TS.

The causes of this event include the failure to perform adequate troubleshooting and post-maintenance testing on February 26, 2005. I&C technicians and their supervision were advised of the proper course of action expected for this type of event, and procedures were revised to clarify the expectations for functional testing following corrective maintenance.